Drilling wells in compartmentalized reservoirs

ABSTRACT

Method of drilling a well, including one method comprising determining a first value indicative of a relative position of a geological bed boundary with respect to a drilling assembly, determining a second value indicative of an optical property of a formation fluid proximate the drilling assembly, and controlling a well trajectory based on the first and second value.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of co-pending U.S. patent application.Ser. No. 12/993,164, filed Nov. 17, 2010, which is a 371 ofinternational Application No. PCT/US2009/041492, filed Apr. 23, 2009,which claims benefit of U. S. Provisional Patent Application Ser. No.61/055,765, filed May 23, 2008. Each of the aforementioned relatedpatent applications is herein incorporated by reference.

BACKGROUND OF THE DISCLOSURE

FIG. 1 illustrates an example environment for the performance of amethod of placing a production or development well 210 into an earthformation F. In the illustrated example, the earth formation F comprisesa first shale deposit or bed 230, a tight sand deposit or bed 231, and asecond shale deposit or bed 232. The beds 230, 231 and 232 are locatedon top of a reservoir R. The reservoir R includes a first poroussandstone bed or reservoir compartment 233, and an intermediate shalebed 234 separating the first reservoir compartment 233 from a secondsandstone bed or reservoir compartment 236. In this example, the firstcompartment 233 contains a first hydrocarbon, and the second compartment236 contains a second hydrocarbon as well as water. The interfacebetween the hydrocarbon and the water is indicated by an oil watercontact (OWC) 235. The earth formation F also comprises a fault 240across which the geological structures are not continuous. Beds 230′,231′, 232′, 233′, 234′ and 236′ correspond to similar beds 230, 231,232, 233, 234 and 236 across the fault 240. Similarly, an OWC 235′corresponds to OWC 235.

In the method depicted in FIG. 1, a first pilot or exploration well 220is initially drilled through the formation F. As the well 220 is beingdrilled, logging while drilling measurements indicative of the physicalproperties of the porous rock immediately surrounding the well 220 areacquired. These measurements may typically include natural gamma ray andresistivity measurements, as well as other types of measurements knownby those skilled in the art. Additionally, or alternatively, the drillstring used to drill the well 220 may be removed from the well 220 and awireline-conveyed tool string may be introduced into the well 220 toacquire measurements indicative of the physical properties of the porousrock immediately surrounding the well 220. Typical operations performedby the wireline-conveyed tool string may include pressure measurements,formation fluid sample collections and sidewall core collections, aswell as other types of measurements and/or collections known by thoseskilled in the art. The measurements collected while drilling and/orwith a wireline tool string are interpreted and used to identify, forexample, a location of the top of the reservoir 236, a type and/oreconomical value of the hydrocarbon contained in the beds 233 and 234,and a location of the OWC 235, among other things. Based on this andoptionally other information, a drill string is introduced in the well220 for a side-tracking well 210. The well 210 is typically a horizontalwell located at a depth that maximizes the economical value of theexpected production from the well 210. The well 210 may be steeredgeometrically along a predetermined trajectory using periodicalmeasurement of the tilt of the bottom hole assembly, or geologicallywith respect to the boundary between the beds 232 and 233 using, forexample, deep resistivity images of the formation encountered by thebottom hole assembly used to drill the well 210.

As shown in FIG. 1, as the well 210 is being drilled in bed 233, it maycross the fault 240. In some cases, such as when the fault 240 ispermeable, the type and/or economical value of the formation fluidpresent in the bed 236′ is similar to the type and/or economical valueof the hydrocarbon present in the bed 233. However, in other cases, thetype and/or economical value of the formation fluid present in the bed236′ is unknown and can not be inferred from measurements collectedwhile drilling the pilot well 220. For example, the type and/oreconomical value of the formation fluid present in the bed 236′ may besignificantly lower than in the bed 233. Thus, the depth or trajectoryof the well 210, selected based on the knowledge of the reservoir fluidalong the well 220, may not lead to a sufficient economical value of thewell 210 past the fault 240. Further, even horizontal variations of thehydrocarbon in the bed 233 may exist. The compositional variations mayrequire updating the trajectory 210 to increase its economical value.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 is a cross-sectional view of a typical formation.

FIG. 2 is a schematic view of apparatus according to one or more aspectsof the present disclosure.

FIG. 3 is a schematic view of apparatus according to one or more aspectsof the present disclosure.

FIGS. 4A and 4B are schematic views of a log according to one or moreaspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various embodiments and/or configurations discussed.Moreover, the formation of a first feature over or on a second featurein the description that follows may include embodiments in which thefirst and second features are formed in direct contact, and may alsoinclude embodiments in which additional features may be formedinterposing the first and second features, such that the first andsecond features may not be in direct contact.

One or more aspects of the methods and apparatus within the scope of thepresent disclosure may be implemented to use measurements indicative ofa relative position of geological bed boundaries with respect to adrilling assembly together with measurements indicative of a methaneconcentration in the formation fluid to control a well trajectory.Methods and apparatus within the scope of the present disclosure mayalternatively or additionally be implemented to use measurementsindicative of a relative position of geological bed boundaries withrespect to a drilling assembly together with measurements indicative ofa formation fluid optical property to control a well trajectory. One ormore aspects of the methods and apparatus within the scope of thepresent disclosure may also or alternatively be used to identifycompartmentalization as a well is being drilled and/or to steer a wellbased on the identified compartmentalization.

FIG. 2 is a schematic view of an exemplary drilling system 50 accordingto one or more aspects of the present disclosure. The drilling system 50can be onshore or offshore. In the exemplary embodiment shown in FIG. 2,a borehole 11 is formed in one or more subsurface formations by rotarydrilling in a manner that is well known. However, implementations withinthe scope of the present disclosure may also or alternatively usedirectional drilling.

A drill string 12 suspended within the borehole 11 comprises a bottomhole assembly 100 which includes a drill bit 105 at its lower end. Thesurface system includes a platform and derrick assembly 10 positionedover the borehole 11, wherein the assembly 10 comprises a rotary table16, a kelly 17, a hook 18, and a rotary swivel 19. The drill string 12is rotated by the rotary table 16, energized by means not shown, whichengages the kelly 17 at the upper end of the drill string 12. The drillstring 12 is suspended from the hook 18 attached to a traveling block(not shown) through the kelly 17 and the rotary swivel 19, which permitsrotation of the drill string 12 relative to the hook 18. A top drivesystem could alternatively or additionally be used.

In the illustrated example implementation, the surface system furthercomprises drilling fluid or mud 26 stored in a pit 27 located near thewell site. A pump 29 delivers the drilling fluid 26 to the interior ofthe drill string 12 via a port in the swivel 19, causing the drillingfluid to flow downward through the drill string 12 as indicated by adirectional arrow δ. The drilling fluid exits the drill string 12 viaports in the drill bit 105, and then circulates upward through theannulus region between the outside of the drill string 12 and the wallof the borehole, as indicated by directional arrows 9. In this wellknown manner, the drilling fluid 26 lubricates the drill bit 105 andcarries formation cuttings up to the surface as it is returned to thepit 27 for recirculation.

The bottom hole assembly 100 of the illustrated example implementationincludes a plurality of logging-while-drilling (LWD) modules 120, 120A,a sampling-while-drilling (SWD) module 130, a measurement-while-drilling(MWD) module 140, a rotary-steerable system and motor 150 (e.g., adirectional drilling subsystem), and the drill bit 105.

Use of the example methods and apparatus described herein may be inconjunction with controlled steering or “directional drilling” using therotary-steerable subsystem 150. Directional drilling is the intentionaldeviation of the wellbore from the path it would naturally take. Inother words, directional drilling is the steering of the drill string sothat it travels in a desired direction. Directional drilling comprisesgeometrical steering, in which the drill bit is typically steered alonga pre-determined path in an Earth formation, and geological steering, inwhich the drill bit is typically steered relative to geological featuresof the Earth formation. Directional drilling may be advantageous inoffshore drilling because, for example, it may enable many wells to bedrilled from a single platform. Directional drilling may also enablehorizontal drilling through a reservoir. Horizontal drilling may enablea longer length of the wellbore to traverse the reservoir, which mayincrease the production rate from the well. A directional drillingsystem may also be used in vertical drilling operations. Often the drillbit 105 will veer off of a planned drilling trajectory because of theunpredictable nature of the formations being penetrated or the varyingforces that the drill bit 105 experiences. When such a deviation occurs,a directional drilling system (e.g., the rotary-steerable subsystem 150)may be used to put the drill bit 105 back on course.

A known method of directional drilling includes the use of a rotarysteerable system (“RSS”). In an RSS, the drill string 12 is rotated fromthe surface, and downhole devices cause the drill bit 105 to drill inthe desired direction. Rotating the drill string 12 greatly reduces theoccurrences of the drill string 12 getting hung up or stuck duringdrilling. Rotary steerable drilling systems for drilling deviatedboreholes into the earth may be generally classified as either“point-the-bit” systems or “push-the-bit” systems. In point-the-bitsystems, the axis of rotation of the drill bit 105 is deviated from thelocal axis of the bottom hole assembly 100 in the general direction ofthe new hole. The hole is propagated in accordance with the customarythree point geometry defined by upper and lower stabilizer touch pointsand the drill bit 105. The angle of deviation of the drill bit 105 axiscoupled with a finite distance between the drill bit 105 and a lowerstabilizer results in the non-collinear condition required for a curveto be generated. There are many ways in which this may be achieved,including a fixed bend at a point in the bottom hole assembly 100 closeto the lower stabilizer, or a flexure of the drill bit 105 drive shaftdistributed between an upper and the lower stabilizer. In its idealizedform, the drill bit 105 is not required to cut sideways because the bitaxis is continually rotated in the direction of the curved hole.Examples of point-the-bit type rotary steerable systems and theiroperation are described in U.S. Patent Applicatiion Publication No.2001/0052428 and U.S. Pat. Nos. 6,401,842; 6,394,193; 6,364,034;6,244,361; 6,158,529; 6,092,610; and 5,113,953, all of which are herebyincorporated herein by reference in their entireties.

In push-the-bit rotary steerable systems, there is usually no speciallyidentified mechanism to deviate the bit axis from the local bottom holeassembly axis. Instead, the requisite non-collinear condition isachieved by causing either or both of upper and lower stabilizers toapply an eccentric force or displacement in a direction that ispreferentially orientated with respect to the direction of holepropagation. There are many ways in which this may be achieved,including non-rotating (with respect to the hole) eccentric stabilizers(displacement based approaches) and eccentric actuators that apply forceto the drill bit in the desired steering direction. Steering is achievedby creating non co-linearity between the drill bit 105 and at least twoother touch points. In some instances, the drill bit 105 is required tocut sideways to generate a curved hole. Examples of push-the-bit typerotary steerable systems and their operation are described in U.S. Pat.Nos. 5,265,682; 5,553,678; 5,803,185; 6,089,332; 5,695,015; 5,685,379;5,706,905; 5,553,679; 5,673,763; 5,520,255; 5,603,385; 5,582,259;5,778,992; and 5,971,085, all of which are hereby incorporated herein byreference in their entireties.

The MWD module 140 is housed in a special type of drill collar, as isknown in the art, and can comprise one or more devices for measuringcharacteristics of the drill string 12 and drill bit 105. The MWD module140 further comprises an apparatus (not shown) configured to generateelectrical power delivered to the downhole system. This may include amud turbine generator powered by the flow of the drilling fluid.However, other power and/or battery systems may also or alternatively beemployed. The MWD module 140 may comprise one or more of measuringdevices configured to measure weight-on-bit, torque, vibration, shock,stick-slip, direction, and/or inclination. The MWD module 140 may alsocomprise capabilities for communicating with surface equipment.

The LWD modules 120, 120A are housed in a special type of drill collar,as is known in the art, and can comprise one or a plurality of knowntypes of logging tools. The LWD modules 120, 120A may be configured tomeasure, process and/or store information, and to communicate with theMWD module 140. The LWD modules 120, 120A may be used to implement aresistivity array having a modular design. For example, each LWD module120, 120A may be used to implement a resistivity module with at leastone antenna that can function as a transmitter or a receiver, whereinthe LWD modules 120, 120A are spaced apart on a drill string andseparated by at least one downhole tool (e.g., the SWD module 130). EachLWD module 120, 120A may comprise at least one antenna coil with amagnetic moment orientation not limited to the tool longitudinaldirection. A spacing between the transmitter and receiver modules may beselected based on expected reservoir thickness. Embodiments within thescope of the present disclosure may also comprise more than two LWDtools, including more that two LWD tools each having an antenna.

The LWD modules 120, 120A may be used to implement a geosteering methodwhile drilling the formation by generating a plurality of formationmodels for the formation, where each of the plurality of the formationmodels includes a set of parameters and a resistivity tool therein andlocations of the resistivity tool differ in the plurality of theformation models. Such method may also include computing predicted toolresponses for the resistivity tool in the plurality of formation models,acquiring resistivity measurements using the resistivity tool in theformation with the resistivity modules 120, 120A, and determining anoptimum formation model based on a comparison between the actual toolresponse and the predicted tool responses. The method may furtherinclude steering a bottom hole assembly based on the optimum formationmodel.

The resistivity measurements collected by the resistivity modules 120,120A may be inverted using a Bayesian method. For example, as a well isbeing drilled (e.g., the well 310 depicted in FIGS. 4A and 4B), themeasurements acquired by the LWD modules 120, 120A may be utilized tocompute a plurality of probability curves (see, e.g., probability curve350 in FIG. 4A, represented in superposition to the geological structureof the formation F). The probability curves may express the magnitude ofthe probability of a geological bed boundary as a function of a relativeposition with respect to the drilling assembly 100. Thus, the localmaxima of any probability curve may be indicative of a relative positionof a geological bed boundary with respect to the drilling assembly 100and/or the drilled well (e.g., the well 310). In addition, theresistivity modules 120, 120A may be configured to be capable ofdetecting a fault (e.g., the fault 240).

Further, the resistivity measurements collected by the resistivitymodules 120, 120A may be configured to determine one or more componentsof the resistivity tensor of the beds delimited by the bed boundaries.Thus, the measurements acquired by the resistivity modules 120, 120A maybe used to identify resistivity contrast in a bed, such as observable atan oil-water contact (e.g., oil-water contacts 235, 235′).

Examples of resistivity imaging tools and methods of use may be found inU.S. Patent Publication No. 2006/0011385 and U.S. Pat. No. 7,093,672,each hereby incorporated herein by reference in their entireties.

The SWD module 130 may comprise a probe 131 configured to be selectivelyextended into sealing contact with the wall of the wellbore 11. In theextended position, the probe 131 is configured to establish fluidcommunication between a flow line in the SWD module 130 and theformation. A pump (not shown) disposed in the SWD module 130 may beenergized for extracting fluids from the formation into the flow line.After mud filtrate has been extracted from the formation immediatelysurrounding the wellbore 11, pristine formation fluid is drawn into SWDmodule 130. A plurality of sensors may be disposed on the flowline inthe SWD module 130 and configured to aid in determining a valueindicative of a methane concentration in the formation fluid, a valueindicative of a formation fluid optical property, and/or a property of ahydrocarbon in the compartment, among other values and/orcharacteristics.

A schematic view of an exemplary flow line 500 disposed in the SWDmodule 130 is shown in FIG. 3. The flow line 500 is equipped with afirst light source 510 configured to emit light in the visible and/orNIR range. The light is directed toward the fluid extracted from theformation and circulating in the flow line 500 through an optical window520. The light emerging from the fluid through a second optical window530 is directed towards one or more optical spectrometers (e.g., afilter spectrometer 540 and a grating spectrometer 550).

The optical density (OD) of the fluid may be determined at one or morepreselected wavelengths. One example of measurement collected by thefilter spectrometer 540 is illustrated by the spectrum log 330 of FIG.4A. The spectrum 330 includes a visual representation of the measuredoptical densities 331 a, 331 b, 331 j corresponding to preselectedwavelengths in the visible and NIR range, and preselected wavelengthwidths. The spectrum log 330 comprises a plurality of bars, thethickness of which represents the amplitude of the measured OD for eachof the wavelengths on, for example, a scale between 0 and 5. In theexample shown in FIG. 4A, the analyzed fluid has a large measured OD 331a, 331 b, and a low measured density 331 j. In addition, these opticaldensities, and optionally the OD measured by the grating spectrometer550, may be used to determine a partial composition 320. In the shownexample, the composition 320 comprises a weight percentage of methane321, a weight percentage of the lumped group comprising ethane, propane,and butanes, and a weight percentage of the lumped group comprisinghexane and hydrocarbon molecules having more than 6 carbon atoms in themolecule. Other compositions (not shown) may also include the weightpercent of carbon dioxide and/or water, among others.

Still referring to FIG. 3, the flow line 500 may also be equipped with asecond light source 560 configured to emit an essentially monochromaticlight beam in the UV range. The light is directed toward the sampledfluid at one or more incident angles. The reflected light may be alsomeasured at one or more reflected angles to, for example, determine thepresence of gas and/or emulsion in the fluid flowing through the flowline 500. Fluorescent light may also be measured at wavelengthsdifferent from the emitted light. The flow line 500 may also be equippedwith a pressure and temperature gauge (e.g., a quartz gauge) 570, aresistivity cell 580, and a density and viscosity sensor 590. Thedensity and viscosity sensor 590 may be configured to analyze theresonance frequency of a rod vibrating in the flow line 500.

FIGS. 4A and 4B depict aspects of obtaining a new well trajectory 310 inthe formation F of FIG. 1 using the drilling system 50 of FIG. 2. FIGS.4A and 4B represent the formation F of FIG. 1, using like or identicalreference numbers to identify common or similar geological structurespresent in FIG. 1. As shown, the well 310 is drilled from left to right.

In contrast to the method depicted in FIG. 1, a pilot well 220 is notrequired to determine the top of the reservoir (e.g., the boundarybetween beds 232 and 233). Indeed, by utilizing the measurementsprovided by the resistivity modules 120, 120A, the top of the reservoirmay be identified even if the BHA 100 is located, for example, 70 feetaway from the top of the reservoir. The curves 350 may be used todetermine the distance between the BHA 100 and geological boundaries.The inverted components of the resistivity sensor corresponding to thebeds 230, 231, 232 and 233 may be used to distinguish between shales,tight sandstones and oil bearing porous sandstones. Thus, as the top ofthe reservoir is identified, the trajectory of the well 310 may bealtered to land the well horizontally in the bed 233.

Also in contrast to the method illustrated in FIG. 1, a pilot well 220is not required to determine the OWC 235 and/or the intermediate shale234. Indeed, by utilizing the measurements provided by the resistivitymodules 120, 120A, the OWC 235 may be identified even if the BHA 100 islocated, for example, 100 feet away from the top of the reservoir.

Once the well 310 has been landed in the bed 233, a sampling operationmay be initiated. The relative location of the bottom hole assembly withrespect to the geological boundaries may be used to initiate fluidsampling and analysis operations based on the detection that ageological boundary has been crossed. Fluid extraction operations mayrequire the drilling operation to be momentarily stopped so that asampling probe 131 may establish an exclusive fluid communication withthe formation F. Fluid extraction may then be initiated by the SWDmodule 130, and may last approximately 30 minutes or more in order toextract mud filtrate from the formation and subsequently obtain pristinereservoir fluid in the sampling tool. During this time, the BHA 100 isnot rotated, increasing thereby the risk that the BHA may stick to theformation. It may be therefore beneficial in some cases to limit thenumber of locations at which the SWD module 130 is used. For example,these locations may be selected based on the relative location of thebottom hole assembly with respect to the geological boundaries, such asonce a geological boundary has been crossed, among other considerations.

The drilling system 55 of FIG. 2 may allow more completecharacterization of the reservoir compartment 233. For example, ahydrocarbon reservoir compartment may be identified by determining (1)the relative locations of the geological boundary of the compartmentwith respect to the well, and (2) at least one property of a hydrocarbonin the compartment. By analyzing the formation fluid extracted from thecompartment 233 using one or more of the sensors shown in FIG. 3, aspectral signature (e.g., optical signature and/or NMR signature) of thefluid may be used to distinguish between a dry gas bearing compartment,a wet gas bearing compartment, a gas condensate retrograde bearingcompartment, a volatile oil bearing compartment, a non volatile oilbearing compartment, and a heavy oil bearing compartment. For example,the spectral signature measured may be provided to a surface operator inthe form of an optical density in the visible range (oil color), apartial composition (e.g., the partial composition 320), and/or a GOR.Thus, as the well 310 is landed in the compartment 233, the drillingsystem 55 may be used to compare fluid properties expected from, forexample, prior knowledge of the formation F (e.g., via offset wells). Ifthe measured property does not match the expected property, thetrajectory of the well 310 may be altered to, for example, intersect thecompartment 136. Additional measurements may be performed in a samecompartment to, for example, detect horizontal composition gradients inthe compartment. The drilling system 55 may in turn be used to adjustthe drilling direction of the well 310 in response to a detectedhorizontal composition gradient to, for example, increase or decreasethe distance separating the well 310 and the top of the reservoir.

As shown in FIG. 4B, the well 310 may eventually cross the fault 240.The fault 240 may be detected from measurements acquired with theresistivity modules 120, 120A. However, in some cases, the resistivitymodules 120, 120A may measure components of the resistivity tensor inthe compartment 234′ having similar values as the measured components ofthe resistivity tensor in the compartment 233. Once a new compartment isbeing drilled, the SWD module 130 may be used to investigate thecompartment using downhole fluid analysis (DFA). In the shown example,the fluid in the compartment 234′ may have the expected partialcomposition 420 and the optical spectrum 430, both based on measurementsperformed in the compartment 233. However, the measured properties mayindicate a different oil as illustrated by measured partial composition520 and optical spectrum 530. Based on this information, as well as thedetected geological boundaries, the well 310 may then be steered awayfrom the oil-water contact and towards the compartment 233′. Once thewell is landed in the compartment 233′, a new downhole fluid analysisoperation may be performed.

In view of all of the above and the Figures, those skilled in thepertinent art should readily recognize that the present disclosureintroduces a method of drilling a well, comprising determining a firstvalue indicative of a relative position of a geological bed boundarywith respect to a drilling assembly, determining a second valueindicative of a methane concentration of a formation fluid proximate thedrilling assembly, and controlling a well trajectory based on the firstand second values. The first value may be obtained with anelectro-magnetic propagation while drilling tool, an electricalinduction while drilling tool, and/or an acoustic while drilling tool.The second value may be obtained with a sampling while drilling tool, anear infrared (NIR) spectrometer, a nuclear magnetic resonance (NMR)spectrometer, and/or at least one of a mass spectrometer and a gaschromatographer. The second value may comprise a gas-oil ratio (GOR).

Another method introduced in the present disclosure comprisesdetermining a first value indicative of a relative position of ageological bed boundary with respect to a drilling assembly, determininga second value indicative of an optical property of a formation fluidproximate the drilling assembly, and controlling a well trajectory basedon the first and second value. The optical property of the formationfluid may be an absorption at one or more wavelengths, wherein the oneor more wavelengths may be at least partially in at least one of thevisible range and the near infrared (NIR) range. The optical property ofthe formation fluid may be a fluorescence intensity at one or morewavelengths, wherein the one or more wavelengths may be at leastpartially in the UV range. The optical property of the formation fluidmay be a reflection intensity at one or more incidence angles at aninterface between the formation fluid and a light transmitting window.

The present disclosure also introduces a method of drilling a wellcomprising identifying a hydrocarbon reservoir compartmentalization bydetermining at least one relative location of a geological boundary ofthe compartment with respect to the well and at least one property of ahydrocarbon in the compartment. Such method further comprises adjustinga well trajectory based on the determined compartmentalization.

The present disclosure also introduces a method of evaluating aformation penetrated by a well, comprising lowering a drilling apparatusin the formation, wherein the drilling apparatus comprises a drillingassembly, an imaging tool, and a fluid sampling tool. The imaging toolis used to determine at least one relative location of a geologicalboundary of a compartment with respect to the well. The drillingassembly is used to extend the well beyond the determined geologicalboundary. The fluid sampling tool is used to extract fluid from theformation located beyond the determined geological boundary. The methodfurther comprises measuring a property of the extracted fluid using atleast one of a density sensor, a viscosity sensor, and an opticalsensor.

The present disclosure also introduces an apparatus comprising animaging tool configured to determine at least one relative location of ageological boundary of a compartment with respect to a well penetratinga subterranean formation, a drilling assembly configured to extend thewell beyond the determined geological boundary, a fluid sampling toolconfigured to extract fluid from the formation located beyond thedetermined geological boundary, and a sensor configured to measure aproperty of the extracted fluid.

The present disclosure also introduces an apparatus comprising means fordetermining a first value indicative of a relative position of ageological bed boundary with respect to a drilling assembly. Suchapparatus also comprises means for determining a second value indicativeof an optical property of a formation fluid proximate the drillingassembly, wherein the optical property is selected from the groupconsisting of: an absorption at one or more wavelengths; a fluorescenceintensity at one or more wavelengths; and a reflection intensity at oneor more incidence angles at an interface between the formation fluid anda light transmitting window. The apparatus further comprises means forcontrolling a well trajectory based on the first and second value. Theoptical property of the formation fluid may be selected from the groupconsisting of: an absorption at one or more wavelengths at leastpartially in at least one of the visible range and the near infrared(NIR) range; and a fluorescence intensity at one or more wavelengths atleast partially in the UV range.

The foregoing outlines features of several embodiments so that thoseskilled in the art may better understand the aspects of the presentdisclosure. Those skilled in the art should appreciate that they mayreadily use the present disclosure as a basis for designing or modifyingother processes and structures for carrying out the same purposes and/orachieving the same advantages of the embodiments introduced herein.Those skilled in the art should also realize that such equivalentconstructions do not depart from the spirit and scope of the presentdisclosure, and that they may make various changes, substitutions andalterations herein without departing from the spirit and scope of thepresent disclosure.

What is claimed is:
 1. A method of drilling a well, comprising:conveying a downhole apparatus within a well penetrating a subterraneanformation; determining, via one or more imaging modules of the downholeapparatus, a first value indicative of a relative position of a boundaryof a geological bed with respect to a drilling assembly disposed on thedownhole apparatus; initiating drawing formation fluid into the downholeapparatus in response to determining that the boundary has been crossedby the downhole apparatus; drawing the formation fluid into the downholeapparatus via a fluid sampling module of the downhole apparatus;analyzing the formation fluid within the downhole apparatus to determinea second value indicative of an optical property of the formation fluid;and adjusting a well trajectory based on the first value and the secondvalue.
 2. The method of claim 1 wherein adjusting a well trajectorycomprises altering the well trajectory based on the first value to landthe well in a geological bed and further altering the well trajectorybased on the second value in response to determining that the opticalproperty does not match an expected property.
 3. The method of claim 1wherein the optical property comprises an optical density, a partialcomposition, a gas oil ration, or a combination thereof.
 4. The methodof claim 1 wherein adjusting a well trajectory comprises steering thewell away from an oil-water contact.
 5. The method of claim 1 whereindetermining a first value comprises collecting one or more formationresistivity measurements and computing probability curves based on theformation resistivity measurements.
 6. The method of claim 1 whereindetermining a first value comprises identifying a resistivity contrastin the geological bed.
 7. The method of claim 1 wherein analyzing theformation fluid comprises determining an optical density of theformation fluid.
 8. The method of claim 1 wherein adjusting the welltrajectory comprises comparing the optical property to an expectedproperty.